There are many methods available by which gas-phase impurities are removed from gas streams. These impurities may comprise carbon dioxide, sulfur oxides, nitrogen compounds, and/or hydrogen sulfide. Some methods are specific to a particular application while others may be useful in purifying gas streams from several sources. These prior art methods may consist of a simple single wash of the stream or complicated multiple-step washes with regeneration stages. The sources of gas streams are nearly as varied as the methods used to treat the streams. Moreover, in many instances the compositional characteristics of a gas stream may differ from site to site as well as change over time at a single site.
More specifically, it will be appreciated by those skilled in the art of gas purification that there currently exist numerous large, unproduced reserves of natural gas in the United States and abroad. As will also be known, the natural gas contained within these unproduced reserves typically contains sulfur compounds, including a substantial amount of hydrogen sulfide (H.sub.2 S). The hydrogen sulfide content of natural gas makes the raw gas unsuitable for most uses. Therefore, in order to utilize natural gas supplies having high concentrations of hydrogen sulfide, the raw feedstock gas must be purified to remove a substantial portion of the hydrogen sulfide. Although the process of the present invention is principally directed to the purification of natural gas streams by the elimination or reduction of hydrogen sulfide, the present invention may be suitable for use in purifying other gas streams where unwanted hydrogen sulfide is present.
The most common process for removing hydrogen sulfide from natural gas, i.e. "sweetening sour gases" utilizes an alkanolamime solution through which the raw feedstock gas is passed. Alkanolamimes act as absorbents for acidic gases, including hydrogen sulfide. The two alkanolamimes which are most commonly utilized in gas purification are monoethanolamine (MEA) and diethanolamine (DEA). Diisopropanolamine (DIA) is also used to some extent in the purification of gas streams as well as methyldiethanolamine (MEDA), the latter being selectives for the absorption of H.sub.2 S in the presence of carbon dioxide. Various other additives are often included such as corrosion and foam inhibitors. In the absorber, H.sub.2 S reacts to form amine sulfide and hydrosulfide. The flow regime in most alkanolamime plants includes the passage of the raw gas upward through an absorber containing the alkanolamine solution. The rich solution is pumped from the bottom of the absorber to a stripping column and may be flashed to remove hydrocarbons remaining from the absorption process. The hydrogen sulfide is removed in the stripping column and the water vapor portion is condensed to be fed back to the absorber. A number of modifications and improvements have been made on this basic process. However, as will be known by those skilled in the art, an amine plant is extremely expensive particularly from the standpoint of initial capitalization.
It is also known to convert H.sub.2 S recovered in this manner to sulfur by firing the hydrogen sulfide in the combustion chamber to convert at least a portion of it to SO.sub.2. The SO.sub.2 is then passed over a catalyst at high temperatures to yield sulfur and water vapors. The sulfur is then isolated by condensing the vapors. This process has a number of drawbacks, including the high temperatures required and the need for a solid catalyst. Moreover, SO.sub.2 is quite corrosive at high temperatures.
It is also known to remove hydrogen sulfide from natural gas using iron oxide. Typically, iron oxide is placed on a carrier such as wood chips or the like. The impregnated carrier is then loaded into a vessel with a liquid. Sour gas is bubbled through the vessel and contacts the iron oxide on the carrier. While this method effectively removes hydrogen sulfide from the gas stream, it is both costly and labor-intensive from the standpoint of maintenance. Moreover, considerable down time is required due to the need to remove the spent wood chips which fuse into a solid mass.
In U.S. Pat. No. 3,849,540 a process for removing hydrogen sulfide from natural gas is disclosed in which the hydrogen sulfide is removed using a catalytic reaction. Therein, natural gas is treated with an aqueous solution containing dissolved oxygen and a transition metal catalyst which, as stated, may comprise a copper salt. In U.S. Pat. No. 4,130,403, membrane separation units are disclosed for use in separating hydrogen sulfide from hydrocarbon streams. In U.S. Pat. No. 3,079,223, a process is disclosed by which hydrogen sulfide in a hydrocarbon stream is removed by contacting the gas stream with fluidized solids containing copper. In U.S. Pat. No. 4,192,854, a process is disclosed for the removal of hydrogen sulfide and ammonia from gaseous streams in which a closed-loop scrubbing of the stream is carried out with a copper sulfate-ammonium sulfate solution to yield a copper sulfide precipitate.
In the present invention, the numerous drawbacks inherent in these prior art methods are overcome by providing a process for removing hydrogen sulfide from gaseous streams which is particularly useful in the removal of hydrogen sulfide from natural gas streams. The process may be operated as a closed-loop system and is both efficient and economical. In addition, the present invention provides a reaction vessel which is conveniently used in carrying out the process of the present invention.